WO2019036731A2 - Solution chimique et ses procédés d'utilisation pour remédier au sulfure d'hydrogène et à d'autres contaminants dans des liquides à base de pétrole et d'autres liquides - Google Patents

Solution chimique et ses procédés d'utilisation pour remédier au sulfure d'hydrogène et à d'autres contaminants dans des liquides à base de pétrole et d'autres liquides Download PDF

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Publication number
WO2019036731A2
WO2019036731A2 PCT/US2018/050913 US2018050913W WO2019036731A2 WO 2019036731 A2 WO2019036731 A2 WO 2019036731A2 US 2018050913 W US2018050913 W US 2018050913W WO 2019036731 A2 WO2019036731 A2 WO 2019036731A2
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Prior art keywords
contaminated liquid
treatment
treatment solution
liquid
hydrogen sulfide
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PCT/US2018/050913
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WO2019036731A3 (fr
Inventor
Cliffton Roe
Linda SCHWEITZER
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Gaps Technology LLC
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Gaps Technology LLC
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Priority to BR112020001417-6A priority Critical patent/BR112020001417B1/pt
Priority to CU2020000006A priority patent/CU24670B1/es
Priority to CA3070600A priority patent/CA3070600C/fr
Priority to DK18916900.6T priority patent/DK3648795T3/da
Priority to EA202090158A priority patent/EA202090158A1/ru
Priority to EP18916900.6A priority patent/EP3648795B1/fr
Priority to PCT/US2018/064015 priority patent/WO2019209379A1/fr
Priority to AU2018421446A priority patent/AU2018421446B2/en
Priority to MYPI2020000424A priority patent/MY200205A/en
Priority to CN201880052704.XA priority patent/CN111032091B/zh
Priority to US16/253,763 priority patent/US10858595B2/en
Priority to US16/254,089 priority patent/US10550337B2/en
Publication of WO2019036731A2 publication Critical patent/WO2019036731A2/fr
Publication of WO2019036731A3 publication Critical patent/WO2019036731A3/fr
Priority to US16/732,559 priority patent/US11286433B2/en
Priority to SA520410999A priority patent/SA520410999B1/ar
Anticipated expiration legal-status Critical
Priority to CONC2020/0001913A priority patent/CO2020001913A2/es
Priority to ECSENADI202014162A priority patent/ECSP20014162A/es
Priority to US16/851,996 priority patent/US11613710B2/en
Priority to US17/080,209 priority patent/US11512258B2/en
Priority to US17/696,359 priority patent/US12215284B2/en
Ceased legal-status Critical Current

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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G19/00—Refining hydrocarbon oils in the absence of hydrogen, by alkaline treatment
    • C10G19/02—Refining hydrocarbon oils in the absence of hydrogen, by alkaline treatment with aqueous alkaline solutions
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D19/00—Degasification of liquids
    • B01D19/0005—Degasification of liquids with one or more auxiliary substances
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F1/00—Treatment of water, waste water, or sewage
    • C02F1/50—Treatment of water, waste water, or sewage by addition or application of a germicide or by oligodynamic treatment
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F1/00—Treatment of water, waste water, or sewage
    • C02F1/66—Treatment of water, waste water, or sewage by neutralisation; pH adjustment
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G19/00—Refining hydrocarbon oils in the absence of hydrogen, by alkaline treatment
    • C10G19/02—Refining hydrocarbon oils in the absence of hydrogen, by alkaline treatment with aqueous alkaline solutions
    • C10G19/04—Refining hydrocarbon oils in the absence of hydrogen, by alkaline treatment with aqueous alkaline solutions containing solubilisers, e.g. solutisers
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G3/00—Production of liquid hydrocarbon mixtures from oxygen-containing organic materials, e.g. fatty oils, fatty acids
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2101/00—Nature of the contaminant
    • C02F2101/10—Inorganic compounds
    • C02F2101/101—Sulfur compounds
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2103/00—Nature of the water, waste water, sewage or sludge to be treated
    • C02F2103/10—Nature of the water, waste water, sewage or sludge to be treated from quarries or from mining activities
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2103/00—Nature of the water, waste water, sewage or sludge to be treated
    • C02F2103/18—Nature of the water, waste water, sewage or sludge to be treated from the purification of gaseous effluents
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F2103/00—Nature of the water, waste water, sewage or sludge to be treated
    • C02F2103/34—Nature of the water, waste water, sewage or sludge to be treated from industrial activities not provided for in groups C02F2103/12 - C02F2103/32
    • C02F2103/36—Nature of the water, waste water, sewage or sludge to be treated from industrial activities not provided for in groups C02F2103/12 - C02F2103/32 from the manufacture of organic compounds
    • C02F2103/365—Nature of the water, waste water, sewage or sludge to be treated from industrial activities not provided for in groups C02F2103/12 - C02F2103/32 from the manufacture of organic compounds from petrochemical industry (e.g. refineries)
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • C10G2300/1055—Diesel having a boiling range of about 230 - 330 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/207—Acid gases, e.g. H2S, COS, SO2, HCN
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/04—Diesel oil
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P30/00—Technologies relating to oil refining and petrochemical industry
    • Y02P30/20—Technologies relating to oil refining and petrochemical industry using bio-feedstock

Definitions

  • the present disclosure relates to novel chemical treatment solutions and methods of using same for treating and remediating sulfur-containing compounds, primarily including H 2 S, and other contaminants in petroleum based liquids and other liquids. More particularly, the present disclosure relates to such treatment solutions and methods in which the solutions are chemically reacted with a petroleum based liquid, or other liquid in a stoichiometrically controlled and efficient manner which safely and efficiently remediates the contaminants.
  • H 2 S Sulfur-containing compounds including H 2 S have long been recognized as undesirable contaminants in hydrocarbon liquids such as crude oil and liquified petroleum gas (LPG), as well as in aqueous solutions such as solutions extracted from the earth along with crude oil and natural gas.
  • H 2 S is a particularly undesirable contaminant because it is highly toxic, corrosive, etc. and generally hydrocarbon liquids should contain less than five ppm H 2 S in order to be acceptable for refining or other processing.
  • Crude oil which is removed directly from the ground may contain H 2 S in concentrations or hundreds, thousands or tens of thousands of ppm, but typically will contain ⁇ 2000 ppm H 2 S, and will generally be somewhat acidic with a pH about 5 to 6.
  • MEA monoethanolamine
  • triazine etc.
  • treatment involving use of caustic material, iron oxide process, zinc oxide, molecular sieve, potassium hydroxide, and a
  • hydrodesulphurization process the amine treatment is usually the most cost effective choice for gas sweetening when significant amounts of acid gases exist; scrubbing of hydrogen sulfide using sodium hydroxide solution is a well established technology in refinery applications; caustic wash process is commonly used as a preliminary step in sweetening liquid hydrocarbons; and since the used solvent in this process cannot be easily regenerated, caustic scrubbers are most often applied where low acid gas (H2S) volumes must be treated.
  • H2S low acid gas
  • a typical caustic treatment used to remediate H 2 S in crude oil involves use of a caustic aqueous solution consisting of up to 20% NaOH by weight.
  • the water and caustic material are used to extract H 2 S from the crude oil into solution, dissociating H 2 S to HS- ion at higher pH, which shifts the equilibrium of H 2 S gas from oil to water.
  • the HS- can react with sodium to form NaHS (sodium bisulfide), or with S 2 - to form Na 2 S (sodium sulfide), for example, plus water as a byproduct according to the following equations.
  • NaHS sodium bisulfide
  • Na 2 S sodium sulfide
  • Aqueous sodium bisulfide (NaHS) is a commercially valuable product.
  • An object of the present invention is to satisfy the above needs in the art.
  • the present inventors have carefully investigated caustic treatment of petroleum based liquids including crude oil for removing H 2 S and other sulfur based contaminants therefrom, and discovered that the conventional method using a caustic aqueous solution consisting of up to 20% NaOH by weight is not efficient, and that the H 2 S can be much more efficiently remediated using a more highly concentrated caustic solution, e.g., including as a primary component 45-55 weight percent of one or more hydroxides, such as sodium hydroxide (NaOH) and potassium hydroxide (KOH).
  • NaOH sodium hydroxide
  • KOH potassium hydroxide
  • H 2 S gas is more soluble in oil than in water, so that a rate-limiting step, in the remediation of H 2 S from crude oil, is the mass transfer of H 2 S from the oil phase into the aqueous phase.
  • hydrocarbon based liquids which may be treated with the treatment solutions and treatment methods of the present invention include those containing molecules of C3 ⁇ 4 to CH 32 .
  • the conventional caustic treatment methods are limited to using caustic solutions of only up to 20 weight percent N aOH because the conventional methods are designed and intended to be partly a liquid-liquid extraction, and partly a chemical reaction to convert the H 2 S gas to a solid sulfurous species. It is conventionally understood that a certain amount of water is needed to permit the chemical reactants to contact with the crude oil or other petroleum based liquid. The larger amounts of water contained in the conventional caustic treatment solutions permit a greater amount of liquid-liquid extraction. Also, it is known that use of excessive amounts of NaOH may damage the crude oil, as well as metal components used handling the crude oil such as pipes and tanks.
  • a highly concentrated aqueous treatment solution comprising primarily one or more hydroxides, such as sodium hydroxide (NaOH) and/or potassium hydroxide (KOH) at a collective concentration of 35-55 weight percent, and preferably at least 45 weigh percent, in water is very effective for treating petroleum based liquids including crude oil, diesel fuel, etc.
  • hydroxides such as sodium hydroxide (NaOH) and/or potassium hydroxide (KOH)
  • the amount of the aqueous treatment solution used for treating the liquids is maintained within an appropriate range, which can vary depending on several factors, including the specific composition of the liquid to be treated, reaction time permitted and the type of remediation desired, e.g., whether there are any restrictions on the amounts of precipitate(s) and gases that may be released from the treated petroleum based liquids.
  • Sodium hydroxide is very effective for use in the treatment solution because it does not harm the petroleum based liquids when used in appropriate amounts, and is relatively inexpensive, although use of a combination of hydroxides is advantageous for more completely reacting with most or all of the sulfides in the petroleum based liquids, noting that there are more than 300 types of sulfides, although hydrogen sulfide H 2 S is by far the main contaminant that must be remediated. Potassium hydroxide is more effective than sodium hydroxide for reacting with some species of sulfides.
  • the treatment solution containing potassium hydroxide (KOH) together with the sodium hydroxide achieves a more complete reaction with all of the sulfur contained in the petroleum based liquids in comparison to just using a concentrated solution of sodium hydroxide.
  • KOH potassium hydroxide
  • Such treatment solution according to the first aspect of the present invention is highly alkaline with a pH of 13 - 14.
  • the present inventors have found that at a standard dosage rate of 0.25 - 6.0 ml of the treatment solution /liter of petroleum based liquid, preferably 1.0-5.0 ml of the treatment solution /liter of petroleum based liquid, is effective for remediating the hydrogen sulfide H 2 S in most petroleum based liquids including crude oil, with the specific amount to be used depending on the characteristics of the particular liquid being treated, including its API viscosity, the particular contaminants it contains, the levels of such contaminants, and allowed reaction time (The term API as used herein, is an abbreviation for American Petroleum Institute).
  • the H 2 S is remediated down to less than 5 ppm from initial concentrations of up to 20,000 ppm.
  • the treatment solution includes sodium hydroxide as the primary hydroxide therein, e.g., at least 90 % of all hydroxides in the solution
  • much of the H 2 S e.g., at least 60% is converted into sodium bisulfide (NaHS) according to the reaction (1) above, which remains dissolved in the treated petroleum liquid, and does not create any significant problems that would need to be addressed.
  • some of the H 2 S is converted into sulfur dioxide (S0 2 ) gas which may be released from the treated petroleum based liquid, depending on the pressure at which the treated liquid is kept.
  • the appropriate dosage rate is substantially, linearly scalable in relation to most or all of the various characteristics.
  • the dosage rate may be toward the lower end of the range
  • the amount of H 2 S is relatively high , e.g. 10,000 ppm - 20,000 ppm the dosage rate may be toward the higher end of the range
  • dosage rates for intermediate amounts of H 2 S would be at correspondingly intermediate values of the range. Similar, linear scalability applies based on the viscosity - API of the liquid and reaction times allowed.
  • the treatment solution may include other components, again, depending on the desired results, as well as on the presence of other contaminants in the petroleum based liquids which are to be remediated.
  • a small amount of a silicate such as potassium silicate and/or barium may be added to the treatment solution to provide an antibacterial function, which may be desirable for killing microbes, including sulfur eating microbes, in the aqueous portion of the treated petroleum based liquid, which includes water in the treatment solution and water produced in the reactions between 3 ⁇ 4S and hydroxide(s).
  • 2- 10 ml of concentrated 29-45 weight percent potassium silicate aqueous solution may be added per liter of the aqueous treatment solution.
  • Potassium silicate comes in various ratios of Si0 2 : K 2 0, but is often represented as K 2 Si0 .
  • Other appropriate antibacterial agent or agents could be used in addition to or as an alternative to silicates, depending on petroleum based liquid being treated.
  • barium (Ba) may be added in an amount of ⁇ 100 ppm of the petroleum based liquid and will, provide an antibacterial function. Barium tends to be more appropriate for use with lighter hydrocarbon based liquids including diesel fuel, as well as aqueous solutions, while potassium silicate tends to be more appropriate for use with heavier hydrocarbon based liquids including crude oil. Also, barium is prohibited in petroleum liquids which are to be refined, as barium has an adverse effect on the refining process.
  • a treatment process according to an exemplary embodiment of the present invention for remediating petroleum based liquids, such as crude oil, to abate 3 ⁇ 4S in the hydrocarbon based liquids includes steps of adding a standard dosage of the treatment solution according to the exemplary embodiment discussed above within a range of 0.25 - 6.0 ml / liter of the petroleum based liquid, preferably within a range of 1.0 - 5.0 ml / liter of the petroleum based liquid, and permitting the treatment solution to react with the petroleum based liquid for relatively short time period of 15 minutes - 24 hours. While the amount of H 2 S in petroleum based liquids can range from a few ppm to more than 100,000 ppm, crude oil from the ground typically contains ⁇ 2000 ppm H 2 S.
  • the discussed standard dosage amount in the exemplary embodiment of the treatment process according to the present invention is generally effective for H 2 S up to 20,000 ppm, If the concentration of H 2 S is higher than 20,000 ppm it may be necessary to increase standard dosage amount appropriately, which may generally involve linear scalability.
  • the treatment process may include additional steps of collecting, discharging and treating any precipitates and/or gases generated by the reactions between the treatment solution and the petroleum based liquids.
  • the most appropriate or optimum dosage amount of the treatment solution within the discussed range will vary, with generally linear scalability, based on a few factors. These factors include: the amount of H 2 S contained in the particular petroleum based liquid, the API viscosity of the petroleum based liquid, and the amount of time permitted for reacting the treatment solution and the petroleum based liquid.
  • the dosage amount of the treatment solution according to the exemplary embodiment of the present invention containing one or more hydroxides such as NaOH, KOH, and possibly an antibacterial agent such as potassium silicate, is appropriately within the standard dosing range, the reaction(s) between the treatment solution and the sulfur containing compounds in the hydrocarbon based liquid, particularly H 2 S, proceed quickly and efficiently.
  • the amount of the treatment solution added is outside of this range, the reactions between the treatment solution and the sulfur containing compounds in the hydrocarbon based liquid may not proceed quickly and/or efficiently.
  • hydroxides such as NaOH and KOH generally do not have any significantly adverse effects on the treated petroleum based liquids, although application of an excessive amount of the solution may render the treated petroleum based liquid caustic which would be damaging to metals such as steel and aluminum used for containing and transporting the treated liquids.
  • the dosage amount of the treatment solution for any given petroleum based liquid may be increased, e.g., to 2 to 5 times the standard dosing rate, if there is a desire to cause the contaminates therein, including sulfur from the H 2 S, to precipitate out of the treated liquid.
  • Having essentially all of the sulfur from the H 2 S remain in the treated petroleum liquid may be a desired result, e.g., it may be desirable to prevent any solids / precipitates from separating out of the treated petroleum liquid because these could cause problems such as build up in and scaling on the structures in which the treated liquid is being transported or stored, and it may be desirable to prevent any gases such as sulfur dioxide (S0 2 ) from being released from the treated liquid to avoid having to capture, treat and/or release same.
  • S0 2 sulfur dioxide
  • the US Government has adopted guidelines that limit the amount of sulfur contained in fuels, and correspondingly it may be necessary to precipitate some or all of the sulfur from the treated liquids in order to meet the guidelines. Further, the sulfur compounds and/or other contaminates remaining in the treated liquid may create difficulties or complications for further processing and/or combustion of the treated liquids. For aqueous solutions to be discharged to a wastewater treatment facility or to be for purposes such as watering crops it would normally be desirable or necessary to remove the remediated sulfur compounds and other
  • the treatment solution may also be used in remediating aqueous solutions containing H 2 S and other contaminants, such as water extracted from the ground with crude oil and natural gas.
  • Remediating 3 ⁇ 4S is a primary focus and advantage of the first exemplary embodiment because 33 ⁇ 4S is very toxic and corrosive, is typically present at elevated levels in crude oil and aqueous solutions extracted from the ground with crude oil or natural gas, and the content of 3 ⁇ 4S in petroleum based liquids and aqueous solutions is highly limited a regulated.
  • Other contaminants which may be remediated and/or removed using the treatment solution according to the first exemplary embodiment include total suspended solids (TSS), bottom sediment and water (BSW), ammonia, heavy metals, etc.
  • the treatment solution according to the first exemplary embodiment is aqueous based and may primarily include one or more hydroxides, such as sodium hydroxide (NaOH) and potassium hydroxide (KOH), at a collective, high concentration of 35-55 weight percent, and preferably at least 45 weight percent, in water, and possibly one or more other components depending on the specific characteristics of the petroleum based liquid being treated, and other factors relating to the treatment.
  • hydroxides such as sodium hydroxide (NaOH) and potassium hydroxide (KOH)
  • KOH potassium hydroxide
  • Characteristics of the petroleum based liquids include the API viscosity thereof, the particular
  • H 2 S is the main contaminant which must typically be remediated in petroleum based liquids, it may be necessary or desirable to also remediate the other contaminants besides 3 ⁇ 4S in the petroleum based liquids, and the other contaminants may also create complications for remediating the H 2 S.
  • H 2 S gas has much greater solubility in petroleum liquids than in water, and at the high pressures at which crude oil exists underground, it is possible for the crude oil to have thousands and tens of thousands of ppm H 2 S therein, although when the crude oil is brought up to ambient atmospheric pressure much of the 3 ⁇ 4S gas may be released from the crude oil according to Henry's Law, and hence the need to abate the H 2 S and prevent it from being released.
  • H 2 S is an acidic compound, crude oil as extracted from the ground and containing a typical amount of H 2 S, e.g. ⁇ 2000 ppm which is mostly in the form gas dissolved in the crude oil, has a moderately acidic pH of about 5 - 5.5.
  • Gaseous H 2 S does not exist in solution above a pH of about 7.
  • the treatment solution according to the first exemplary embodiment of the invention contains a large percentage of hydroxide(s), is basic with a pH of about 13-14, and when added to the petroleum liquid increases the pH thereof.
  • the water and hydroxide are used to extract H 2 S from the crude oil into the water, dissociating H 2 S to HS- ion at higher pH, which shifts the equilibrium of H 2 S gas from oil to water. Then, the HS- can react with sodium to form NaHS (sodium bisulfide), or with S 2 - to form Na 2 S (sodium sulfide), for example, plus water as a byproduct according to the following equations.
  • NaHS sodium bisulfide
  • S 2 - sodium sulfide
  • Aqueous sodium bisulfide (NaHS) is a commercially valuable product.
  • the present inventors have carefully investigated treatment of petroleum based liquids including crude oil for removing H 2 S and other sulfur based contaminants therefrom using an aqueous hydroxide solution, and discovered that the conventional methods, using a caustic aqueous solution consisting of up to 20 weight percent sodium hydroxide (NaOH) are not efficient, and that the H 2 S can be much more efficiently remediated using a more highly concentrated, aqueous hydroxide solution; e.g., including as a primary component 35-55 weight percent, and preferably at least 45 weight percent, of one or more hydroxides, such as sodium hydroxide (NaOH) and potassium hydroxide (KOH).
  • NaOH sodium hydroxide
  • KOH potassium hydroxide
  • H 2 S gas is more soluble in oil than in water, so that a rate-limiting step in the remediation of H 2 S from crude oil is the mass transfer of H 2 S from the oil phase into the aqueous phase.
  • liquid-liquid extraction aspect of the conventional methods is actually not that important in comparison to the chemical reaction aspect, e.g., because the initial solubility of H 2 S into water, as given by Henry's Law, is low;
  • OH " that may be used in the treatment solution according to the first exemplary embodiment, many of these have undesirable characteristics associated therewith, including that they would introduce other contaminants into the treated petroleum based liquids which may require further remediation step(s), high cost, etc.
  • iron, other metals, calcium, barium, and chlorides interfere with heat and cracking in refining processes and would have to be removed from treated crude oil before it is refined.
  • sodium, potassium, magnesium, manganese are permitted in refining processes as long as the content is not too high, e.g., ⁇ 250 ppm.
  • Sodium hydroxide is very effective for use in the treatment solution because it does not harm the petroleum based liquids when used in appropriate amounts.
  • NaOH is used exclusively or primarily as the hydroxide in the treatment solution at a concentration of about 50 weight percent according to the first embodiment, and the solution is used at a standard dosing rate to treat crude oil in a treatment process according to an exemplary embodiment of the present invention as discussed herein, this may increase sodium content in the treated crude oil from about 10 ppm to 50 ppm. At such content level the sodium does not detrimentally affect the crude oil to any appreciable extent. Further, the treatment solution does not introduce any other contaminants into the crude oil that would require further remediation step(s), and the treatment solution is relatively inexpensive. Potassium hydroxide (KOH), magnesium hydroxide (Mg(OH) 2 ), and manganese hydroxide (Mn(OH) 2 , Mn(OH) 4 ) are other suitable hydroxides.
  • the treatment solution according to the first embodiment may contain a blend of 70 - 99.9 parts NaOH : 0.1 - 30 parts KOH, at a total concentration of 35-55 weight percent, and preferably at least 45 weight percent in water.
  • such treatment solution according to the first exemplary embodiment of the present invention is highly alkaline with a pH of 13 - 14.
  • the treatment solution may include other components, again, depending on the presence of other contaminants in the petroleum based liquids which are to be remediated, as well as on the desired results of the treatment process.
  • a small amount of a silicate such as potassium silicate may be added to the treatment solution to provide an anti bacterial function, which may be desirable for killing microbes, including sulfur eating microbes, in the aqueous portion of the treated petroleum based liquid, including water in the treatment solution and water produced in the reactions between H 2 S and the hydroxide(s).
  • a dosage of 2-10 ml of concentrated 29-45 weight percent potassium silicate aqueous solution may be added per liter of the aqueous treatment solution to achieve such function.
  • Potassium silicate comes in various ratios of Si0 2 : K 2 0, but is often represented as K 2 Si0 3 .
  • Other appropriate anti-bacterial agent or agents could be used in addition to or as an alternative to silicates, depending on the particular liquid being treated.
  • barium (Ba) may be added in an amount of ⁇ 100 ppm of the liquid being treated, whether a petroleum based liquid or aqueous solution, and will provide an antibacterial function. Barium tends to be more appropriate for use with lighter hydrocarbon based liquids including diesel fuel and for treating contaminated aqueous solutions, while potassium silicate tends to be more appropriate for use with heavier hydrocarbon based liquids including crude oil.
  • barium is prohibited in petroleum liquids which are to be refined as barium has an adverse effect on the refining process. Therefore, barium is not preferred in the practice of the present invention.
  • the pH of the aqueous portion of the liquids in the treatment cell may be adjusted to a level such as 8.5 - 7.0, at which the ammonia is converted to ammonium ion (NH 4 +) and thereby prevents the ammonia from being released in gas form.
  • reducing the pH of the treatment solution may also affect the reactions between hydroxide and H 2 S.
  • S 7- ions in the water are converted to HS " ions, which is one step closer to 3 ⁇ 4S, so that there will be more residual H 2 S in the produced water when the pH is adjusted lower and less residual H 2 S in the produced water when the pH is adjusted higher.
  • the treatment solution according to the first exemplary embodiment should produce a pH of around 7-10 in the petroleum liquid being treated, whereas if ammonia is a concern, the pH should not be raised above 8.5.
  • the appropriate pH ranges for remediating both H 2 S and NH 3 and depending on which of these contaminants is present and at what levels the pH can be suitably adjusted to achieve an optimum result.
  • remediation of H 2 S is a primary focus of the invention, and would normally be a primary factor in determining the appropriate pH for the treated liquid.
  • overdosing with treatment solution may increase the pH above 9, and thus increases the risk of producing more ammonia gas. Hence this is another reason why the dosage rate for the treatment solution should be maintained within a standard range as discussed herein.
  • An alternative approach for remediating ammonia in the produced water is to remove the ammonia from the aqueous portion of the liquid in the treatment cell via an ion exchange process.
  • the rag impurities in the petroleum based liquid may be conveniently and efficiently removed from the hydrocarbon based liquid using the same treatment solution and treatment processes according to the exemplary embodiments of the present invention as used for reacting with the H 2 S and other sulfur-containing compounds in the hydrocarbon based liquid and aqueous solutions, although this will typically require a higher dosage rate of the treatment solution as compared to the appropriate dosage rate for treating H 2 S and other sulfur-containing compounds.
  • the treatment solution according to the exemplary embodiment is added to the liquid being treated at 2 or 3 times the standard dosage rate for treating H 2 S and other sulfur-containing compounds, the excess treatment solution will more surely cause most or ail of the rag impurities to precipitate out of the treated liquid as discussed herein.
  • the treatment solution functions to separate the rag components from the hydrocarbon based liquid and transfer these components into the produced water, from which they may precipitate or settle to the bottom of the treatment cell where they can be easily removed for further treatment, sale or discarding.
  • a treatment solution according to the first exemplary embodiment of the present invention may be added to petroleum based liquids at a controlled dosage amount, whereby the treatment solution directly reacts with H 2 S and is very effective for remediating contaminants in the liquids, including H 2 S and other sulfur-containing contaminants, provided that the dosage amount of the aqueous treatment solution is maintained within an appropriate range, which can vary depending on a matrix of several factors such as discussed herein.
  • the alkaline treatment solution according to the first exemplary embodiment When added to the crude oil, it increases the pH of the crude oil and the hydroxide(s) therein quickly and efficiently remediate the H 2 S down to 5 ppm or less, e.g., if NaOH is the hydroxide it will react with the H 2 S according to the equations (1), (2) discussed above to generate NaHS (sodium bisulfide) and/or Na 2 S (sodium sulfide).
  • the invention provides unexpected results in that it is counterintuitive to limit the amount of water in the remediation process according to the exemplary embodiment of the present invention because this limits chemical contact with the contaminants in the petroleum based liquids such as crude oil, e.g., the chemical reactants are mostly ionic and readily dissolve in water, but not in the petroleum based liquids such as crude oil.
  • the present inventors have unexpectedly found that since the chemical reactions involved, e.g., equations (1), (2) above, produce water, the produced water can readily diffuse through the oil as it is produced because the caustic solution has good migration tendencies through many of the petroleum based liquids being treated, and that it is unnecessary to initially provide any significant amount of water in the treatment process apart from the water in the treatment solution in order for the petroleum-based liquid to be effectively treated for remediation of sulfur-containing contaminants, including H 2 S.
  • An exemplary treatment process according to the present invention as discussed herein is not a wash type process, but rapid chemical reactions that greatly reduce the mass transfer of the gas to aqueous phase.
  • the treatment solution according to the first exemplary embodiment has good migration tendencies in petroleum based liquids with low or moderate viscosities, e.g., above an API viscosity of 25°, and will readily disperse therein. Dispersion of the produced water and the treatment solution throughout the liquid being treated may be improved with a relatively small amount of mixing, e.g., via an impeller rotating at low-medium speeds such as 50-200 rpm and/or heating.
  • What the treatment process according to the present invention does differently, in comparison to the conventional treatment processes, is to essentially reduce the initial amount of water to the minimum effective amount, while carefully limiting the amount of hydroxides and possibly other reactants in the treatment solution to appropriate amounts, for reacting with the contaminants in the petroleum based liquid being treated based on considerations of stoichiometry, desired reaction rate and specific result desired, and by this the efficiency of the process is increased in multiple aspects.
  • One aspect is that excessive amounts of the treatment solution are not used and wasted.
  • Another aspect of increased efficiency is that more of the petroleum-based liquid may be treated for any given size treatment batch /tank because there is less amount of water in the batch / tank.
  • the volume of resulting waste that must be removed and possibly treated is reduced as well.
  • highly concentrated aqueous solutions of hydroxides are particularly, highly concentrated aqueous solutions of hydroxides.
  • a first treatment process according to an exemplary embodiment of the present invention for remediating petroleum based liquids, such as crude oil, by abating 3 ⁇ 4S in the hydrocarbon based liquids includes steps of adding a standard dosage of the treatment solution according to the exemplary embodiment discussed above within a range of 0.25 - 6.0 ml / liter of the petroleum based liquid, preferably within a range of 1.0 - 5.0 ml / liter of the petroleum based liquid, and permitting the treatment solution to react with the petroleum based liquid for time period of 15 minutes - 24 hours. While the amount of H 2 S in petroleum based liquids can range from a few ppm to more than 100,000 ppm, crude oil from the ground typically contains ⁇ 2000 ppm H 2 S.
  • the discussed standard dosage amount in the exemplary embodiment of the treatment process according to the present invention is generally effective for H 2 S us to 20,000 ppm, If the concentration of H 2 S is higher than 20,000 ppm it may be necessary to increase standard dosage amount appropriately, which may generally involve linear scalability.
  • the first exemplary treatment process may include additional steps of collecting, discharging and treating any precipitates and/or gases generated by the reactions between the treatment solution and the petroleum based liquids.
  • the most appropriate or optimum dosage amount of the treatment solution within the discussed range will vary, with generally linear scalability, based on a few factors. These factors include: the amount of 3 ⁇ 4S contained in the particular petroleum based liquid, the API viscosity of the petroleum based liquid, and the amount of time permitted for reacting the treatment solution and the petroleum based liquid. For example, if the treatment liquid a medium to light crude oil and the amount of H 2 S is relatively low, e.g. 20 ppm - 100 ppm the most appropriate dosage rate may be toward the lower end of the range, whereas if the amount of H 2 S is relatively high, e.g.
  • the first exemplary treatment process may be conveniently carried out essentially wherever the contaminated liquids may be present, e.g., in open bodies of the liquids, in conjunction with a transport tanker or other vessel in which the liquids are being transported, at a wellhead where the liquids are being extracted from the ground, in open or closed tanks, in an enclosed pipeline through which the contaminated water or other liquid is being transported, etc.
  • API viscosity of the liquid decreases, the most appropriate amount of the treatment solution will generally increase.
  • the treatment solution including hydroxide(s)
  • Different types of petroleum liquids include light crude oil (API viscosity > 31.1°), medium crude oil (API viscosity between 23.3° and 31.1°), heavy crude oil (API viscosity ⁇ 23.3°), bunker fuel (API viscosity approximately 6°), diesel fuel (API viscosity approximately 34°), etc.
  • Petroleum based liquids with an API viscosity of less than 10° are heavier than water, are extremely viscous and will sink in water.
  • a most appropriate dosage amount may be 1-2 ml / liter of petroleum based liquid, while for medium viscous liquids (API viscosity of 20°-30°) such as light, medium or heavy crude oil, a most appropriate dosage amount may be 2-3.5 ml / liter of petroleum based liquid, and for highly viscous petroleum based liquids (API viscosity of 15° or less), such as bunker fuel, a most appropriate dosage amount may be 5-7 mi / liter of petroleum based liquid.
  • reaction time permitted there may no restriction thereon and the treatment solution may be permitted to react for any suitable time such as 15 minutes - 24 hours at a most appropriate dosage rate based on the concentration - amount of H 2 S contained in the particular liquid and the API viscosity of the liquid.
  • reaction time is limited, e.g., limited to an amount of time required to transport the petroleum based liquid to a desired destination for unloading after the treatment solution has been added to the liquid, limited to less than 30 minutes based on desired productivity, etc.
  • a most appropriate dosage amount to be added to the liquid according to a treatment process of the present invention may be increased above a dosage amount determined based on based on the concentration - amount of H 2 S contained in the particular liquid and the API viscosity of the liquid, e.g., increased to an amount that will assure essentially complete remediation of the H 2 S contained in the particular liquid within the time permitted. For example, if a normal reaction time required to fully remediate H 2 S contained in the particular liquid is 2 hours, but the permitted reaction time is only 1 hour, a most appropriate dosage amount may be double a most appropriate dosage amount determined based on the concentration - amount of H 2 S contained in the particular liquid and the API viscosity of the liquid.
  • the first treatment method according to the exemplary embodiment of the present invention is very effective for remediating the hydrogen sulfide H 2 S in most petroleum based liquids including crude oil.
  • the H 2 S is remediated down to less than 5 ppm from initial concentrations of up to 20,000 ppm.
  • Addition of the treatment solution to the petroleum based liquid at the appropriate dosage rate will raise the pH of the liquid, e.g., crude oil at a pH of about 5.0-5.5 will increase to a pH of about 5.8-6.2, which changes the valence of the dissolved H 2 S gas in the liquid and permits substantially all of the H 2 S to be abated and changed into other compounds which are not toxic.
  • the pH of the liquid e.g., crude oil at a pH of about 5.0-5.5 will increase to a pH of about 5.8-6.2, which changes the valence of the dissolved H 2 S gas in the liquid and permits substantially all of the H 2 S to be abated and changed into other compounds which are not toxic.
  • the hydroxide(s) in the treatment solution may not efficiently react with H 2 S and other sulfur containing compounds in the hydrocarbon based liquids, the
  • the treated petroleum based liquids may not meet government-established, contaminant limits.
  • the amount of the treatment solution added / liter of petroleum based compound is more than 6.0 ml, the additional amount of the treatment solution may not improve the efficiency of remediating the H 2 S and other sulfur containing compounds in the hydrocarbon based liquids per se, and may simply increase the cost of the treatment.
  • addition of an excessive amount of the treatment solution above the standard dosage rate may be desirable for various reasons, such as those discussed herein.
  • the treated liquid is likely to be caustic and have a relatively high pH, which can be undesirable because it may corrode metals including steel and aluminum.
  • the dosage amount used in a treatment process according to the present invention is moderately or significantly excessive in comparison the optimum dosage amount based on stoichiometry and other
  • the present inventors have found that if the reactions involved in the treatment process are properly control led by dosing the treatment solution within the standard range of 0.25 - 7 ml / liter of petroleum based liquid, preferably within a range of 1.0 - 5.0 ml / liter of the petroleum based liquid, and a reaction time of 15 minutes to 24 hours according to the exemplary embodiment of the present invention, then the NaOH in the treatment solution will react with the sulfur preferentially over other species in the petroleum based liquids such as crude oil and will not harm the petroleum based liquids.
  • the present inventors have found that a dose of the treatment solution within the standard range does not harm the petroleum based liquids and completely remediates the 3 ⁇ 4S contained therein down to 5 ppm or less, and typically down ⁇ substantially 0 ppm. Any residual caustic waste resulting from the method according to the first aspect of the invention will typically not harm the petroleum based compounds because it will be a relatively small amount and also tends to separate from the hydrocarbon based liquids and move toward the bottom of the treatment cell, thereby no longer making contact with the oil, and may be readily separated from the petroleum based compounds.
  • the treatment solution contains sodium hydroxide as the primary hydroxide contained therein, e.g., at least 90% of the hydroxides
  • much of the H 2 S e.g., at least 60% is converted into sodium bisulfide (NaHS) according to the reaction (1) above, which remains dissolved in the treated petroleum liquid, and does not create any significant problems that would need to be addressed, e.g., this would not prevent the crude oil from being accepted as sweet, high grade crude oil.
  • NaHS sodium bisulfide
  • H 2 S may be converted into sulfur dioxide (S0 2 ) gas (upon stirring which allows air containing oxygen to get into the oil, which may released from the treated petroleum based liquid, depending on the pressure under which the treated liquid is kept.
  • S0 2 sulfur dioxide
  • hydroxides including NaOH are reducing agents and would not produce sulfur dioxide or elemental sulfur if the treated petroleum liquid is not exposed to air.
  • the sulfide/bisulfide can be oxidized to S02 or elemental sulfur. All sulfide species are the same oxidation state (-2) and NaOH is not changing the oxidation state. Similar reactions would occur for other hydroxides included in the treatment solution.
  • a study performed showed that for crude oil with a starting concentration of about 8 ppm Na and about 1000 ppm H 2 S, after treatment using 3 ml of the treatment solution / liter of the crude oil, the final concentrations were about 40 ppm Na and 0 ppm H 2 S.
  • Sodium has no adverse effects in the crude oil refining process as long as the concentration of sodium is generally ⁇ 250 ppm.
  • the abatement of the 3 ⁇ 4S by the treatment process according to the exemplary embodiment of the present invention is desirably non-reversible, unlike H 2 S abatement achieved by a conventional amine treatment process which uses an amine such as monoethano! amine (MEA) or triazine for treating 3 ⁇ 4S in crude oil.
  • MEA monoethano! amine
  • the sulfur contained in the treated oil may revert back to H 2 S over time, especially if the treated oil is heated, which is undesirable.
  • the treatment process according to the exemplary embodiment applying the treatment solution according to the exemplary embodiment at the standard dosing rate discussed above will normally increase the pH of the petroleum liquid being treated, e.g., crude oil, to a value of 7.0 or less. At this level any ammonia in the liquid will be converted to ammonium (N3 ⁇ 4 + ), which desirably remains in solution, unlike ammonia which may be released as a toxic gas, and ammonium does not cause any significant problems or complications when further treating the petroleum liquid, e.g., in a refining process, or combusting the treated liquid.
  • the petroleum liquid being treated contains any rag impurities, these will for the most part also remain in solution when the liquid is treated in the first treatment process according to the exemplary embodiment applying the treatment solution according to the exemplary embodiment at the standard dosing rate discussed above.
  • This may be desirable or undesirable as some rag impurities may create problems or complications when further treating the petroleum liquid, e.g., in a refining process, or combusiing the treated liquid.
  • the present invention makes it possible to cause sulfur containing compounds, rag impurities, and other remaining impurities remaining in the treated petroleum liquid to precipitate out of the liquid if so desired.
  • a second treatment process involves increasing the dosage amount of the treatment solution for any given petroleum based liquid, e.g., from 2 to 5 times the standard dosing rate, if there is a desire to cause the contaminates therein, including sulfur from the H 2 S and rag impurities, to precipitate out of the treated liquid and/or be released from the treated liquid as gas such as sulfur dioxide. While it is certainly possible to increase the dosage amount above 5 times the standard dosing rate in the second treatment process according to the present invention, generally there is no significant benefit in doing so.
  • Having essentially all of the sulfur from the H 2 S and the rag impurities remain in the treated petroleum liquid may be a desired result, e.g., it may be desirable to prevent any solids / precipitates from separating out of the treated petroleum liquid because these could cause problems such as build up in and scaling on the structures in which the treated liquid is being transported or stored, and it may be desirable to prevent any gases such as sulfur dioxide (S0 2 ) from being released from the treated liquid to avoid having to capture and remediate same, e.g., in a scrubbing process.
  • S0 2 sulfur dioxide
  • the rag impurities and other contaminants such as metals may be precipitated out of the petroleum based liquid being treated, especially if these are likely to cause undesired problems or complications in further processing or combustion of the liquids, and by increasing the dosage rate of the treatment solution by 2 to 5 times the standard dosing rate in the treatment process according to the second exemplary embodiment of the present invention, this is effective to cause the rag impurities and other contaminants to precipitate out of the treated liquid. Further, depending on how much the standard dosage amount of the treatment solution is increased for the treatment process, this may be controlled to generate different precipitates and gases which separate out of the treated liquid.
  • Increasing the dosage rate of the treatment solution by 2 to 5 times the standard dosing rate according to the second exempl ary embodiment of the treatment process according to the invention will increase the pH of the treated liquid to a level above that which it would be if the liquid was treated in the first exemplary embodiment involving an appropriate dosage within the standard dosage range.
  • the pH of the treated liquid is likely to be in a range of 6 - 7.
  • the pH of the treated liquid is likely to be in a range of 7-8
  • the pH of the treated liquid is likely to be in a range of 8 - 8.5
  • the liquid contains ammonia, again, it would not be desirable to increase the pH above 8.5 as this may result in release of ammonia gas.
  • the treatment solution according to the exemplary embodiment includes NaOH as the primary hydroxide therein, e.g., NaOH constitutes at least 90% of the hydroxides therein, and the treatment solution is applied at 2 times the appropriate dosing rate within the standard dosing range for the liquid, this will, increase the pH of the treated liquid to a value in a range of about 7.2 - 8.0, and at such pH, much of the 3 ⁇ 4S and other sulfur containing contaminants in the treated liquid will be converted to a hydrate of sodium sulfide such as Na 2 S-9H 2 0 according to the reactions (1) and (2) above, and should precipitate out of the treated liquid.
  • NaOH sodium sulfide
  • the treatment process according to the second exemplary embodiment involves addition of the treatment liquid at a higher dosage rate of 3 to 5 times the standard dosage rate, this may increase the pH of the liquid to 8.5 or above, and at such pH much of the 3 ⁇ 4S and other sulfur containing contaminants in the treated liquid may be converted to elemental sulfur, which precipitates out of the treated liquid.
  • the increased dosage rates in the treatment process according to the second exemplary embodiment will generally speed up the reaction rate for remediating the H 2 S in the petroleum liquid to some extent, which may be desired.
  • a treatment solution according to the first exemplary embodiment of the present invention i.e., an aqueous treatment solution including as a primary component 35-55 weight percent, and preferably at least 45 weight percent, of one or more hydroxides, such as sodium hydroxide (NaOH) and potassium hydroxide (KOH) in water, and possibly other components such as potassium silicate or barium in appropriate small amounts as discussed above which provide an antibacterial function, may also be used in processes for treating contaminated aqueous solutions including 3 ⁇ 4S as a primary contaminant to be remediated, as well as other sulfur containing contaminants and other contaminants,
  • the treatment processes for the aqueous solutions include essentially the same steps and considerations for establishing an appropriately controlled dosage amount as discussed above in relation to the treatment of petroleum based liquids.
  • the treatment solution again, directly reacts with 3 ⁇ 4S and is very effective for remediating 3 ⁇ 4S, other sulfur-contain contaminants and other contaminants in the aqueous liquids, provided that the dosage amount of the treatment solution is maintained within an appropriate range, which can vary depending on a matrix of several factors including most of the same factors as discussed in relation to treatment of petroleum based liquids.
  • viscosity of the aqueous solutions should not be an important factor that needs to be considered when determining an appropriate dosage rate of the treatment solutions as most contaminated aqueous solutions have very low viscosity, whereby the treatment solutions according to the present invention will readily migrate and disperse throughout the aqueous solutions at the standard dosage rates with or without agitating the aqueous solution.
  • the appropriate dosage amount is generally, linearly scalable in relation to each of the relevant factors.
  • an appropriate dosage amount of the treatment solutions according to the present invention to be used in a treatment process for treating either a petroleum based liquid or an aqueous liquid will be essentially the same provided the liquids contain the same amounts of H 2 S, other sulfur compounds and other contaminants, the desired reaction rate for the treatment process is the same, and the desired outcome of the treatment process is the same in terms of whether the remediated contaminants are to remain in solution or are to be released from the treated liquid in particular form(s).
  • an appropriate dosage amount of treatment solution is, again, within the standard dosing rate of 0.25 - 6.0 ml, preferably 1.0-5.0 ml / liter of aqueous solution, with the most appropriate dosage rate within such range determined based on a matrix of considerations, including the amounts of H 2 S and other specific contaminants contained in the particular aqueous solution and the desired reaction time permitted for reacting the treatment solution and the aqueous solution.
  • the dosage amount may be appropriately increased within range of 2-5 times the standard dosing rate.
  • One exemplary treatment process for treating a contaminated aqueous solution according to the present invention includes steps of includes steps of adding a standard dosage of the treatment solution according to the exemplary embodiment discussed above within a range of 0.25 - 6.0 ml / liter of the petroleum based liquid, preferably within a range of 1.0 - 5.0 ml / liter of the petroleum based liquid, and permitting the treatment solution to react with the petroleum based liquid for time period of 15 minutes - 24 hours.
  • H 2 S soluble and gaseous H 2 S which can be in aqueous solutions
  • the discussed standard dosage amount in the exemplary embodiment of the treatment process according to the present invention is generally effective for H 2 S up to 20,000 ppm, and hence the standard dosage amount will be appropriate for most contaminated aqueous solutions.
  • the first exemplary treatment process may include additional steps of adding other components to cause flocculadon or precipitation of undesired components remaining in the treated aqueous solution , as well as collecting, discharging and treating any precipitates and/or gases generated in and /or released from the treated aqueous solutions.
  • the treatment process may be modified to adding an increased dosage amount of the treatment solution, e.g., within range of 2-5 times the standard dosing rate, if it is desired for the treatment solution to cause the remediated H 2 S, other sulfur compounds and other contaminants to be released from the treated liquid as precipitates, and also possible as gases.
  • sodium bisulfite NaHS0 3
  • sodium bisulfite sodium bisulfite
  • sodium bisulfite When added at a relatively low concentration, e.g., 0.001 - 0.05 ppm / liter of liquid being treated, sodium bisulfite is very effective for displacing dissolved gases such as methane contained in the aqueous solutions as these liquids are treated and transported via a tanker truck, pipeline or other manner, so that the displaced gas may be captured, collected and sold. This is, of course, very desirable and advantageous.
  • aqueous solution of sodium bisulfite may be highly concentrated, e.g., 70-90% wt/wt, may be added to the exemplary treatment solutions according to the present invention at an appropriate rate to achieve a concentration of 0.001 - 0.05 ppm / liter of liquid being treated, While addition of sodium bisulfite may be particularly suitable for treating aqueous solutions, it may also be added to a treatment solution used for treating petroleum based liquids. Significantly, however, if sodium bisulfite is to be used in treating crude oil or other petroleum based liquids it should be added in hydrated form, whether in power or liquid, to function efficiently. Examples Of Treatment Processes According to the Prese t Invention
  • Example 1 The method according to the first exemplary embodiment of the present invention was used for treating crude oil (API viscosity 29°) containing approximately 1000 ppm H 2 S as the primary contaminant and having a pH of 5.2. There were, of course, other contaminants in the crude oil, but these were not a significant concern in comparison to the H 2 S.
  • the treatment solution was prepared by combining 1 liter of NaOH aqueous solution at 50.5 weight percent, 10 ml of OH aqueous solution at 45 weight percent, and 4 ml of potassium silicate aqueous solution at concentration of 40 weight percent potassium. Three ml of the treatment solution were added / liter of the crude oil, and dispersed therein with stirring at 100 rpm at a temperature of 25 °C while the treated liquid was exposed to air, which raised the pH of the crude oil to
  • Example 2 The conditions in Example 2 were exactly the same as in
  • Example 1 except that 6 ml, or double the standard dosage amount of 3 ml, of the treatment solution were added / liter of the crude oil, which raised the pH of the crude oil to approximately 7.7.
  • this Example falls under the second exemplary treatment process of the present invention.
  • the treated crude oil was tested and showed 0 ppm H 2 S with most of the H 2 S, > 95%, being converted primarily to sodium sulfide (Na 2 S) and to a much lesser extent elemental sulfur, both of which precipitated out the treated crude oil, and the balance of the H 2 S being converted into sulfur dioxide gas most of which was released from the treated crude oil.
  • Na 2 S sodium sulfide
  • elemental sulfur both of which precipitated out the treated crude oil
  • the other sulfur compounds besides H 2 S and other contaminants in the crude oil were also precipitated and released from the treated crude oil.
  • the precipitates were separated from the treated crude oil for further processing, sale and/or disposal, and the treated crude oil containing 0 ppm H 2 S could be sold as sweet, high grade crude oil.
  • the aqueous solution contain much of remaining NaOH, KOH, and sodium silicate was withdrawn from the treatment cell, and the NaOH, KOH, and sodium silicate were recovered therefrom.
  • Example 3 The conditions in Example 3 were exactly the same as in
  • Example 1 except that 8 ml of the treatment solution were added / liter of the crude oil, which raised the pH of the crude oil to approximately 8.4. After one hour the treated crude oil was tested and showed 0 ppm H 2 S with most of the H 2 S, > 95%, being converted primarily to elemental sulfur in various forms (S 2 , S 4 , S 6 , Sg) which
  • the precipitates were separated from the treated crude oil for further processing, sale and/or disposal, and the treated crude oil containing 0 ppm H 2 S could be sold as sweet, high grade crude oil.
  • the aqueous solution contains much of the remaining NaOH, KOH, and sodium silicate was withdrawn from the treatment cell, and the NaOH, KOH, and sodium silicate were recovered therefrom.
  • Example 4 The method according to the first exemplary embodiment of the present invention was used for treating a contaminated aqueous solution containing approximately 800 ppm H 2 S as the primary contaminant and having a pH of 5.0. Again, there were other contaminates in the aqueous solution, but these were not a significant concern in comparison to the H 2 S. Three ml of the treatment solution were added / liter of the aqueous solution and dispersed therein with stirring at 100 rpm at a temperature of 25°C, which raised the pH of the aqueous solution to approximately 6.6.
  • the treated aqueous solution was tested and showed 0 ppm H 2 S with most of the H 2 S, > 90%, being converted to sodium bisulfite (NaHS) which remained in the treated crude oil, and the balance of the H 2 S being converted into sulfur dioxide gas, some of which remained dissolved in the treated liquid and some of which was released.
  • an amount of ferric chloride (FeCl 3 ) was added to the treated aqueous solution and dispersed therein with stirring at 100 rpm, and after 1 hour the ferric chloride flocculated most of the sodium bisulfite and contaminants remaining in the aqueous solution and the flocculated materials precipitated and separated from the aqueous solution.
  • the treated aqueous solution then had 0 3 ⁇ 4S and sufficiently low concentrations of other
  • the treatment solution according to the present invention may also be used in other treatment processes.
  • One such other use is for treating toxic and noxious gases, including H 2 S and S0 2 , produced in various processes such as coal-burning electricity generating power plants, etc.
  • the present inventors have found that the treatment solution according to the first exemplary embodiment of the present invention is appropriate for removing undesirable components from such gases via a bubbling type scrubbing process.
  • the present inventors have found that if the highly concentrated caustic solution is used at normal strength or perhaps diluted with an additional water down to 40-80% of normal strength, the treatment solution is very effective for removing undesirable components, including sulfur, from such gases via a bubbling type scrubbing process. These gases were captured and then scrubbed via a bubbling process in which the captured gases were bubbled through the treatment solution used in the first exemplary embodiment of the present invention which was diluted by 50 weight percent with additional water.

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Abstract

L'invention concerne un procédé de traitement pour remédier à un liquide contaminé contenant plus de 5 ppm de sulfure d'hydrogène (H2S), comprenant les étapes consistant à : préparer une solution de traitement contenant une solution aqueuse contenant 1 composé d'hydroxyde ou plus, dans laquelle une concentration collective du ou des composés d'hydroxyde dans la solution aqueuse est dans une plage de 35-55 % en poids et la solution aqueuse constitue au moins 95 % de la solution de traitement ; ajouter au liquide une quantité d'une solution de traitement suffisante pour réduire une concentration de sulfure d'hydrogène dans le liquide contaminé à une valeur ≤ 5 ppm sur la base de la stœchiométrie de réactions entre le(s) composé(s) d'hydroxyde et le sulfure d'hydrogène dans le liquide ; et disperser la solution de traitement dans le liquide et à permettre à la solution de traitement de réagir avec le liquide contaminé pendant une certaine durée jusqu'à ce qu'une concentration de sulfure d'hydrogène dans le liquide soit réduite à une valeur ≤ 5 ppm.
PCT/US2018/050913 2017-08-01 2018-09-13 Solution chimique et ses procédés d'utilisation pour remédier au sulfure d'hydrogène et à d'autres contaminants dans des liquides à base de pétrole et d'autres liquides Ceased WO2019036731A2 (fr)

Priority Applications (19)

Application Number Priority Date Filing Date Title
BR112020001417-6A BR112020001417B1 (pt) 2018-04-23 2018-12-05 Composições químicas e métodos para corrigir sulfeto de hidrogênio e outros contaminantes em líquidos à base de hidrocarbonetos e soluções aquosas
CU2020000006A CU24670B1 (es) 2018-04-23 2018-12-05 Proceso y solución de tratamiento de base acuosa para la remediación de sulfuro de hidrógeno y otros contaminantes en líquidos
CA3070600A CA3070600C (fr) 2018-04-23 2018-12-05 Compositions et methodes de remediation du sulfure d'hydrogene et d'autres polluants dans les liquides et les solutions aqueuses a base d'hydrocarbures sans la formation de precipite ou d'ecaillage
DK18916900.6T DK3648795T3 (da) 2018-04-23 2018-12-05 Kemiske sammensætninger og fremgangsmåder til reducering af indholdet af hydrogensulfid og andre kontaminanter i carbonhydridbaserede væsker uden dannelse af præcipitat
EA202090158A EA202090158A1 (ru) 2018-04-23 2018-12-05 Композиции и способы для удаления сероводорода и других загрязнений из жидкостей на основе углеводородов и водных растворов
EP18916900.6A EP3648795B1 (fr) 2018-04-23 2018-12-05 Compositions chimiques et procédés pour réduire la teneur en sulfure d'hydrogène et autres contaminants dans des liquides à base d'hydrocarbures sans formation de précipités.
PCT/US2018/064015 WO2019209379A1 (fr) 2018-04-23 2018-12-05 Compositions et procédés pour réduire la teneur en sulfure d'hydrogène et autres contaminants dans des liquides à base d'hydrocarbures et des solutions aqueuses
AU2018421446A AU2018421446B2 (en) 2018-04-23 2018-12-05 Compositions and methods for remediating hydrogen sulfide and other contaminants in hydrocarbon based liquids and aqueous solutions
MYPI2020000424A MY200205A (en) 2018-04-23 2018-12-05 Chemical compositions and methods for remediating hydrogen sulfide and other contaminants in hydrocarbon based liquids and aqueous solutions without the formation of precipitates or scale
CN201880052704.XA CN111032091B (zh) 2018-04-23 2018-12-05 用于治理烃基液体和水溶液中的硫化氢和其他污染物的组合物和方法
US16/254,089 US10550337B2 (en) 2017-08-01 2019-01-22 Chemical compositions and methods for remediating hydrogen sulfide and other contaminants in hydrocarbon based liquids and aqueous solutions without the formation of precipitates or scale
US16/253,763 US10858595B2 (en) 2017-08-01 2019-01-22 Chemical solution and methods of using same for remediating hydrogen sulfide and other contaminants in petroleum based and other liquids
US16/732,559 US11286433B2 (en) 2017-08-01 2020-01-02 Compositions and methods for remediating hydrogen sulfide in hydrocarbon based liquids
SA520410999A SA520410999B1 (ar) 2018-04-23 2020-01-08 تركيبات وطرق كيميائية لإصلاح كبريتيد الهيدروجين وملوثات أخرى في السوائل المعتمدة على هيدروكربون ومحاليل مائية بدون تكوين رواسب أو قشور
CONC2020/0001913A CO2020001913A2 (es) 2018-04-23 2020-02-21 Composiciones químicas y métodos para remediar el ácido sulfhídrico y otros contaminantes en líquidos y soluciones acuosas basadas en hidrocarburos sin formación de precipitados o incrustaciones
ECSENADI202014162A ECSP20014162A (es) 2017-08-01 2020-02-26 Composiciones químicas y métodos para remediar el ácido sulfhídrico y otros contaminantes en líquidos y soluciones acuosas basadas en hidrocarburos sin formación de precipitados o incrustaciones
US16/851,996 US11613710B2 (en) 2017-08-01 2020-04-17 Methods of remediating liquid compositions containing sulfur and other contaminants
US17/080,209 US11512258B2 (en) 2017-08-01 2020-10-26 Chemical compositions and methods of using same for remediating low to moderate amounts of sulfur-containing compositions and other contaminants in liquids
US17/696,359 US12215284B2 (en) 2017-08-01 2022-03-16 Compositions and methods for remediating hydrogen sulfide in hydrocarbon based liquids

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US201762539699P 2017-08-01 2017-08-01
US62/539,699 2017-08-01

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US16/253,763 Continuation US10858595B2 (en) 2017-08-01 2019-01-22 Chemical solution and methods of using same for remediating hydrogen sulfide and other contaminants in petroleum based and other liquids

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US11905457B2 (en) 2021-09-01 2024-02-20 Gaps Technology, Llc Chemical compositions and methods of using same for remediating sulfur-containing compositions and other contaminants encountered in drilling wells
US12084615B2 (en) 2021-09-13 2024-09-10 GAPS Technology, LLC. Chemical compositions and in-situ methods of using same for remediating sulfur-containing compositions and other contaminants in fluids being extracted from the earth
US12187972B1 (en) 2022-08-29 2025-01-07 GAPS Technology, LLC. Aqueous solutions and methods of using same for remediating contaminants in contaminated gasses
US12600913B2 (en) 2022-11-22 2026-04-14 Gaps Technology, Llc Liquid based chemical compositions and treatment systems and treatment methods using same for reducing sulfur content in hydrocarbon based liquids including crude oil

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